Antero Resources Corporation (AR) Earnings Call Transcript & Summary

Greetings, and welcome to the Antero Resources Second Quarter 2023 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce to you, Brendan Krueger, VP of Finance. Thank you, Brendan. You may begin.

Thank you. Good morning. Thank you for joining us for Antero's Second Quarter 2023 Investor Conference Call. We'll spend a few minutes going through the financial and operating highlights, and then we'll open it up for Q&A. I would also like to direct you to the homepage of our website at www.anteroresources.com, where we have provided a separate earnings call presentation that will be reviewed during today's call. Today's call may contain certain non-GAAP financial measures. Please refer to our earnings press release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. Joining me on the call today are Paul Rady, Chairman, CEO and President; Michael Kennedy, CFO; and Dave Cannelongo, Senior Vice President of Liquids Marketing and Transportation; and Justin Fowler, Senior Vice President of Natural Gas Marketing. I will now turn the call over to Paul.

Thank you, Brendan. I'll start my comments on Slide #3, titled Drilling and Completion Efficiencies. After a record-breaking first quarter operationally, the strong momentum continued in the second quarter. Completion stages averaged more than 11 per day in the second quarter, a 40% improvement compared to the 2022 average and over a 90% increase from 2019 levels. Drill Outs which are the process of drilling out the plugs in each stage of the horizontal portion of the well exhibited the same success during the quarter. Drill-outs averaged over 4,000 feet per day during the second quarter, up 9% from the 2022 average and over 50% increase from the 2019 levels. Faster drill outs and completion times have resulted in significantly shorter cycle times, as shown on the bottom of the page. Since 2019, our cycle times have decreased by 65% and averaged just 151 days in the second quarter. In June, we had the fastest cycle times in our company history at 129 days. These cycle times reflect the total number of days it takes on average from first spud on a pad to turning the entire pad to sales. As a reminder, we averaged 6 wells per visit per pad. Shorter cycle times mean higher capital efficiency. Highlighting this point, we completed roughly 60% of our 2023 budgeted completion stages during the first 6 months of 2023. Now let's turn to Slide #4, titled Antero Wells continue to outperform peers. In addition to the drilling and completion records, we continue to see increases in well productivity. Chart on this slide highlights well productivity trends versus our peers since 2020. As illustrated on the page, Antero's average cumulative equivalent production per well is 20% higher than the peer average over this time. This differentiates Antero from its peers with many companies having already drilled their best acreage, our long core inventory life continues to deliver stronger results each year. Now let's turn to Slide #5. Faster cycle times and improving well performance led to the increase in our 2023 production guidance. This gain in capital efficiencies is highlighted by our 5% total production growth in the second quarter compared to the year ago period. Our production growth was driven by 16% liquids growth, while natural gas was essentially flat year-over-year. These capital efficiency gains also reduce our maintenance capital budget as illustrated in the chart on the right-hand side of the page, we currently expect 10% lower D&C capital in 2024, driven by operational efficiency gains alone. To be clear, the lower capital outlook for 2024, assumes we maintain our increased 2023 production level, the potential for a rollover in service costs suggest that there could be further reductions in next year's capital budget but it's too early to assume that those service costs will come to fruition today. Now to touch on the current liquids and NGL fundamentals I'll turn it over to our Senior Vice President of Liquids Marketing and Transportation; Dave Cannelongo for his comments.

Thanks, Paul. While C3+ prices as a percent of WTI are currently low, it is important to remember that the second quarter is historically weak for NGL prices. Moving into the second half of 2023 and further into 2024, we see tailwinds emerging from normal seasonal demand drivers, upside in the Chinese petrochemical market and supply moderation due to rig reductions in liquids-rich basins. Starting with propane. Although absolute propane inventory levels have remained elevated throughout the first half of 2023, days of supply has generally been trending within the 5-year range during the same period. This indicates that the current higher stock levels are to a large degree necessary to support the substantial growth that the U.S. market has experienced primarily in exports, but also domestic petrochemical demand. Turning to propane exports, which are highlighted on Slide #6, we have seen consistent strength throughout 2023, with total U.S. propane exports averaging 1.6 million barrels per day year-to-date. This is 300,000 barrels per day or approximately 25% higher than the same period last year. Propane exports also reached a new record high in the second quarter of 1.9 million barrels per day in late June, according to weekly EIA data. In the domestic market, propane demand should improve in the coming months, from a new propane dehydrogenation or PDH facility that is starting up in the Gulf Coast, followed by seasonal crop drying and heating demand as we move through the remainder of 2023 into 2024. Turning to the Chinese market. Although there have been various headwinds to economic recovery post-COVID, we have seen some recent data points showing improvement in the petrochemical sector there. Chinese integrated polypropylene margins from PDH units have shown dramatic improvements year-to-date, increasing from outright negative levels in February to almost $300 per metric ton in May. Unsurprisingly, utilization rates in Chinese PDH units have been closely correlated with this margin improvement. Operating rates have improved from the low [indiscernible] during the first quarter, as shown on Slide #7, reaching a year-to-date high of 69% in June 2023, which was the highest rate observed in over a year on the back of higher overall PDH capacity from new facility commissioning during that timeframe. We believe the rapid uptick observed in PDH utilization in recent months in response to margin improvement highlights the value of having spare petrochemical capacity already in place when demand recovery occurs. This is something that we have talked about in previous quarters as well and is a bullish factor over the long-term as the property sector improves in China and worldwide. Turning to supply. There has been a lot of attention on the rig reductions in gas-focused basins but also wanted to highlight the rig reductions we have seen this year in liquids-focused regions. Slide #8, titled rig counts dropping in key liquids basins shows the rig count changes since the beginning of 2023 for the total U.S. and for several key liquids-rich basins. We are showing both the outright rig decrease and the reduction on a percentage basis to illustrate the magnitude of the impact in each region. There have been substantial year-to-date [ rig ] declines in the Eagle Ford, which is down 26%, the SCOOP/STACK, which is down 30% and the Bakken, which has dropped 20%. So while the U.S. C3+ supply is still growing overall, which we believe is ultimately needed to supply the global market, the rate of growth has been tempered by this drilling slowdown. This trend presents upside for C3+ pricing as we look ahead in 2024 and beyond as the effect of the rig count reductions play out. With that, I will turn it over to Justin Fowler, Senior Vice President of Natural Gas Marketing.

Thanks, Dave. I'll start with comments on the natural gas macro. Turning to Slide #9, titled Peer-leading exposure to premium markets. As a reminder, we sell substantially all of our natural gas out of basin, including approximately 75% to the LNG corridor. Our firm transportation portfolio provides us with direct exposure to the growing LNG demand along the Gulf Coast. This slide illustrates average basis differentials for 2024 through 2027. Premiums to NYMEX Henry Hub that we realized our firm transportation have improved since the beginning of the year. In particular, you can see TGP 500 pricing relative to Henry Hub has increased by $0.15 year-to-date. This increase reflects the anticipation start-up of the Plaquemine LNG facility in 2024, which TGP feeds directly into. Antero has significant exposure to this premium market with the nearly 600 MMcf a day of capacity on that pipeline. Meanwhile, on a local basis, where the majority of our peers have significant exposure remains at a steep discount to NYMEX Henry Hub through 2027 despite the recent approval of the MVP pipeline. Next, let's discuss the industry response to lower natural gas prices. Slide #10, depicts the historical relationship between NYMEX natural gas prices and the rig count in the Haynesville. We discussed this slide on our fourth quarter 2022 conference call back in February. At that time, the Haynesville rig count was 73 rigs. Based on the historical response by producers in that basin, when NYMEX prices fell below $3, we communicated an expectation that rigs would fall by at least 25 to 30 rigs. As it stands today, the Haynesville rig count has declined by 38% or 25 rigs from peak levels. This point is driven home further when looking at the reduction in completion crews in the Haynesville, which is shown on Slide 11. Since the beginning of the year, the completion crew count has declined by 36% from 28 to 18 crews. While the decrease in drilling rigs will have a downward impact on 2024 supply, this reduction in completion crews will have a more immediate impact on supply this year. The sharp decline in drilling rigs and completion crews combined with the basin's steep decline profile is expected to help balance the U.S. natural gas market and provide support to gas prices. In addition to a moderated supply outlook, demand trends continue to shift toward natural gas. Let's turn to Slide #12, titled Power Burn Demand Growth. This chart shows that natural gas power burn demand has increased every year for 10 consecutive years. 2023 looks likely to set new record highs. Despite the warmer than usual winter that led to softer demand to start the year off, 2023 power burn is averaging 3.3 Bcf a day or 14% higher than the 5-year average. This July is forecasted to average over 46 Bcf per day, which was set a new monthly record. In fact, just yesterday, we hit a new daily power burn record of over 51 Bcf. With that, I will turn it over to Mike Kennedy, Antero's CFO.

Thanks, Justin. I'll be brief in my comments today. But I want to re-emphasize the points that Paul made earlier on Antero's peer-leading capital efficiency. Slide #13, highlights the results of our peer group under each company's maintenance capital program. By definition, higher capital efficiency must drive either higher production volumes for the same capital or lower capital with the same production volume, while attempting to target a maintenance capital program, Antero's volumes actually grew 5% compared to the year ago period. Conversely, when our peer group attempted to target a maintenance capital program, their volumes actually declined by 4% year-over-year. This is shown in the chart at the top of the slide. The chart at the bottom of the slide compares the peer group's capital required per Mcfe of production. As a rule of thumb, internally, we view each $100 million change of capital to result in approximately [ 100 million ] a day change in production, both up and down. Over the last year, we grew nearly $175 million a day, which implies that our capital efficiency gains have reduced true maintenance capital by roughly $175 million, all else equal. Adjusted for this volume growth Antero would have the lowest CapEx per Mcfe of its peer group at just $0.66 per Mcfe. Against the peer group averages, Antero's capital program is significantly more efficient, 40% below our natural gas peers. Looking ahead, we expect to maintain 2024 production at our raised production guidance levels on a capital program that we expect to be at least 10% lower than 2023, with all of the lower capital amount due to our capital efficiency. This raised production guidance also continues to assume a more conservative ethane outlook as we risk the timing of the Shell ethane Cracker startup. Lower capital, combined with the higher natural gas strip leads to substantial free cash flow in 2024 and beyond. At the same time, we remain committed to our return of capital policy, which targets returning 50% of our free cash flow to shareholders. With that, I will now turn the call over to the operator for questions.

[Operator Instructions] Our first question comes from the line of Arun Jayaram with JPMorgan.

Yes. My first question is for Dave. Dave, you highlighted just the bullish export trends on propane. And I was wondering if you could give us some thoughts on what do you think has been driving the higher inventory levels? And just thoughts on how you see inventories potentially normalizing on the propane side as we move into winter?

Well, I think the main thing was really the mild winter we had. I think we talked about that maybe on a prior call that, that, coupled with some petrochemical maintenance during the winter time, added roughly 20 million, 21 million barrels to the absolute inventory level. So if you strip that out, we're down in close to the middle of the 5-year range, obviously, even at a lower level on a days of supply basis. So that's been the main driver that I would say play a role there. And then the other piece on the exports, I think we just continue to see strong buying demand, the [ arcs ] are open, using a lot of the ships that are coming online, but there's still roughly 26 vessels yet to come online this year through the remainder. So that will continue to drive freight costs down even though we have this much higher export stack and see some tailwinds there for us as well.

Great. And my follow-up, maybe for Mike. I wanted to get your thoughts on hedging strategy. It seems like Mike, we're in an environment where the market is quite constructive on 2025 gas prices, just given the LNG incremental export demand and maybe investors are appreciating it if some of the gas producers can add some insurance in 2024. Just to get -- call it a floor on your cash flows for '24. So I want to get thoughts on hedging strategy? And could we see Antero looking to add some hedges just given the improvement in strip pricing over the last few weeks?

Yes. Thanks, Arun, Paul here. Well, as you're saying, we too are positive on the natural gas market. There's positive momentum, as you know, in the futures prices [indiscernible] '24 is above 350, '25 and '26 are approaching $4. So pretty healthy. But the other factors we see that give us a little bit of tailwind is that as we've covered here, rig counts, completion crew counts are declining and obviously, that lowers supply. We're all following -- we as an industry are following LNG, the build-outs, the increased demand, people signing up for more and more LNG facilities. And that's happening right now, where more and more facilities will go FID. And then we touched on just the yesterday's record power burn, but the -- systematically, we're seeing higher power burns setting new records such as yesterday's 51 Bcf. So -- as you're aware, Antero is in good shape, have a strong balance sheet. Our leverage is less than 1x. So we're being patient and watching the market and its tailwinds. And we've hedged, of course, years ago and had success at it, but we worked pretty carefully and bide our time. So that's where we are.

The next question comes from the line of Bertrand Donnes with Truist.

On the capital program on the 2024 comments, in the prepared remarks, you noted that you could see additional drops if maybe service costs come down from here. Could you maybe just touch on what the 10% drop includes? Does it use kind of a full year '23 average and then applies it to '24. Is it maybe what you're expecting for the end of the year and then dragging that forward? And then -- just want to give you a chance 1 of your peers is starting to talk about '25. So is there anything that would prevent you from maybe holding that 10% drop into '25 or what it looks like out there?

Yes. So just holding today's cost in the '24 flat, no service cost or -- reductions are incorporated in that. It's because of our capital efficiency and the well productivity, and we grew 5% year-over-year. It's actually maintained that you need about 100,000 less lateral feet. And so when you do the math on that, that's the 10% reduction just at today's costs. So '24 is down that 10% without any service cost help. '25 is actually lower than '24 because as we continue to be at maintenance capital, our declines -- our natural declines continue to decline as well as you add more and more base and get little less steep production and [ less wedge ]. So '25 was below '24 right now. So extremely capital-efficient program continues to improve. And you can see that in our production growth at the same capital, and you'll see it in '24 and '25 with lower capital amount.

That's great. And then just second one is maybe to talk about your potential LNG strategy. Does a tolling agreement make sense for Antero? Or are you seeing anything -- any other structures that maybe would work best for your approach to maybe capture some of the international pricing?

Yes. We have 75% of our production that goes to the LNG corridor. So we have so much exposure to that pricing down there and they're such a large market player in order to attract our gas just even on a spot basis, really is going to be a lot of competition and really going to result in a pretty significant premium, we think, the pricing. So that's our exposure [indiscernible] to these -- we, of course, evaluate all agreements, but you're talking really small volumes and really big commitments. I think that 1 million tons is about a $2 billion commitment over the timeframe, and that's for like [ 100 million ] a day. So we don't have to make those commitments. We already have all the transport and all the production that gets down to the Gulf. So we'll get exposure to sort of spot pricing and then having to compete to buy our gas.

Our next question comes from the line of David Deckelbaum with TD Cowen.

Mike, I think this first one is for you. I just wanted to dig in a little bit on just the CapEx progression into '24. I think we all understand you're not including cost deflation. But can you characterize a bit maybe, obviously, you were employing a maintenance program, but you grew 5% this year. Some of those benefits, I guess, help in '24. But -- can you kind of put some bookends around how many wells you have to do in '24 versus '23 and how you think about sort of the well productivity gains for Antero itself in '23 versus '22?

Yes. So David, I mentioned it's lateral feet really because wells -- our wells continue to lighten in laterals. So we'll have a bit longer in '24 than we did in '23, pretty much every year to go a tad longer. So that's why I mentioned or referenced to 100,000 feet. So we'll have to do 100,000 feet less than we did this year to maintain that around the 3.4 Bcfe level. And so when you just do our well cost on that 100,000 feet, that's how you get the [ $90 million ] less of capital required to maintain. It's maintaining the same productivity, although our wells continue to be more productive. Right now, we're just elevating the shape of the curve and the front end and have not increased the EURs, but that could come later as the well productivity performance continues to be ahead of our expectations.

Is that front ends being influenced by [ choke ] management changes or completion designs? Or is that just geology?

I think we're being conservative in our not applying that throughout the curve and the life of the well and just trying to wait and take a wait-and-see approach and see that continues throughout time.

Appreciate that. And just a follow-up on -- you talked about free cash flow generation, especially in '24 as the curve inflects higher. But I think the last update we all had from you around cash taxes we had you kind of paying some cash taxes this year and that number going higher. Can you give us an update on what you think your cash tax burden is going to be over the next several years with this recent downdraft in commodity pricing?

Yes. We don't foresee any cash taxes through '25 in any material really in '26. So not for the next 3 to 4 years. And with the prices in '23, that's kept us out of really any exposure to [ AMT ] qualification as well. So we don't see any cash taxes for at least the next 3 years.

The next question comes from the line of Umang Choudhary with Goldman Sachs.

My first question was a couple of follow-ups on the capital spending commentary which you made. Can you give us any color around your expectations for cost deflation heading into next year? and on [ lower land ] spending. And then you made a point that spending would be lower in 2025 as the decline rate for the shallow. Any color you can provide there would be great as well.

Yes. On the completions, I think we have, of course, our service contracts around drilling and completions really have been locked in '23. That's why you don't see it there. But I think -- we've seen recent deals 5% to 10% lower than where our current contracts are. So I think that's a good starting point for '24 on potential savings there. And then looking at past '24, it's another 5% to 10% lower capital than that 10% we talked about for '24 versus '23. So it just continues to shallow and continues to go lower as our decline [ shallow ].

Great. And quickly on the LPG side of the equation. It sounds like you think that the lower supply from the U.S. with current rig reductions and improvement in demand from China, we should expect an inflection in pricing. Any color you can provide in terms of when do you think the pricing could inflect -- it's kind of a challenging macro to make predictions here, but any -- do you feel like it's a kind of a winter event as demand starts to pick up also from heating, which can drive that inflection in pricing?

Yes, Umang, I would say, yes. It's -- as we head into the fourth quarter, a couple of things that will be happening along. As Justin mentioned in his comments on the gas side. As you see rig counts that are out there is still -- it takes some time to see the effect of that on the supply side, maybe we're starting to see that here recently just with some of the weaker EIA reports over the last several weeks where the propane builds have underwhelmed up versus expectations to the bullish side for us. But the other things, if you look at how propane is pricing right now relative to naphtha, it's doing its normal seasonal summertime spread that encourages propane to continue to be economic and a steam cracker as we head into the winter time -- as we saw this last winter and every winter before that, that decouples and propane price at higher percentages of naphtha throughout the wintertime. And then we also -- if you look at just how naphtha is pricing globally -- [indiscernible], it's been different since the start of the war in the Ukraine. But even right now on the forward curve, naphtha is discounted relative to where it was this past winter. And obviously, the war was still incurring then we think there's some upside to naphtha, upside to propane, this [indiscernible] that's not reflected in the forward curve. And then as I mentioned earlier in my remarks, maybe to Arun's question, the freight rates are anticipated to come down this winter as well. So multiple factors that should cause propane quite a bit of upside relative to what the forward curve is showing today in the low- to mid-70s.

The next question comes from the line of Subhasish Chandra with the Benchmark Company.

Mike, just to confirm your response to the cost [ curve ]. So -- the 10% as you've stated multiple times, purely capital efficiency and another 5% to 10% is expected could occur in '24 from materials and service cost deflation?

There's that potential. I wouldn't say -- in Paul's remarks, he talked about it maybe too early to forecast that. That's why we're not including that. But it seems that's where the market is trending with the lower rig count, lower completion crews working in the basins.